Wang, Yang (China University of Petroleum – Beijing and Pennsylvania State University) | Cheng, Shiqing (China University of Petroleum – Beijing) | Zhang, Kaidi (Lusheng Petroleum Development Co., Ltd, SINOPEC Shengli Oilfield Company) | Xu, Jianchun (China University of Petroleum – East China) | Qin, Jiazheng (China University of Petroleum – Beijing) | He, Youwei (China University of Petroleum – Beijing and Texas A&M University) | Luo, Le (China University of Petroleum – Beijing) | Yu, Haiyang (China University of Petroleum – Beijing)
Pressure-transient analysis (PTA) of water injectors with waterflood-induced fractures (WIFs) is much more complicated than hydraulic fracturing producers due to the variation of fracture properties in the shutting time. In plenty of cases, current analysis techniques could result in misleading interpretations if the WIFs are not well realized or characterized. This paper presents a comprehensive analysis for five cases that focuses on the interpretation of different types of pressure responses in water injectors.
The characteristic of radial composite model of water injector indicates the water erosion and expansion of mini-fractures in the inner region. The commonplace phenomena of prolonged storage effect, bi-storage effect and interpreted considerably large storage coefficient suggest that WIF(s) may be induced by long time water injection. Based on this interpreted large storage coefficient, fracture half-length can be obtained. In the meanwhile, the fracture length shrinks and fracture conductivity decreases as the closing of WIF, which has a considerable influence on pressure responses. Results show that the upward of pressure derivative curve may not only be caused by closed outer boundary condition, but also the decreasing of fracture conductivity (DFC). As for multiple WIFs, they would close successively after shutting in the well due to the different stress conditions perpendicular to fracture walls, which behaves as several unit slopes on the pressure derivative curves in the log-log plot.
Aiming at different representative types of pressure responses cases in Huaqing reservoir, Changqing Oilfield, we innovatively analyze them from a different perspective and get a new understanding of water injector behaviors with WIF(s), which provides a guideline for the interpretation of water injection wells in tight reservoirs.
A polymer pilot in the 8 TH reservoir in Austria showed promising results. The Utility Factors were below 2 of kg polymer injected / incremental barrel of oil produced (polymer cost are 2 – 4 USD/kg). Furthermore, substantial incremental oil was produced which might result in economic field implementation. The results triggered the planning for field implementation of polymer flooding.
To optimize the economics of field implementation, a workflow was chosen ensuring that the uncertainty was covered. 1200 geological models were generated covering a variety of different geological concepts. These geological models were clustered based on the dynamic response into 100 representative geological realizations and then used for history matching.
For infill drilling, probabilistic quality maps can be used to find locations. However, injection and production well optimization is more challenging. Introducing probabilistic incremental Net Present Value (NPV) maps allows for selection of locations of injection and production well patterns.
The patterns need to be optimized for geometry and operating parameters under uncertainty. The geometry was optimized in a first step followed by operating parameter optimization. In addition, injectivity effects of vertical and horizontal wells due to the non-Newtonian polymer rheology were evaluated. The last step was full-field simulation using the probabilistic NPV map, optimized well distance and operating parameters.
The resulting Cumulative Distribution Function of incremental NPV showed a Probability of Economic Success (PES) of 91 % and an Expected Monetary Value of 73 mn EUR.
A miscible injectant was used in a single injection well pilot in the Yates field to mobilize remaining oil in the gas cap and accelerate gravity drainage. Nitrogen, CO2 and recycled gas injection, all immiscible with Yates oil due to low original and current reservoir pressure, have been used historically to assist the gas-oil gravity drainage (GOGD) development. The result of immiscible injection has been a lowering of the gas-oil contact, a thinning of the oil column, and leaving a remaining oil saturation in the gas cap of up to 40 percent. A hydrocarbon mixture rich in ethane and propane and miscible with Yates oil was injected in a CO2 injector for six months after which the well was returned to pure CO2 injection.
Data collection during the pilot included repeat saturation logging of a newly drilled observation well, well tests of nearby horizontal producers, frequent gas and oil sampling, and chromatographic analysis. Phase behavior PVT experiments were also conducted which confirmed miscibility of the injectant and improvement over CO2 injection. Numerical simulation of pilot performance was also used as part of the interpretation.
Pilot results to date show a doubling of oil rate at peak over base oil decline, breakthrough in horizontal producers within 3-5 months matching an a priori prediction from numerical simulation, 10 percent reduction in oil saturation in the target interval in the gas cap, and the return of two wells to continuous production after having been shut-in due to high gas-oil ratios. Early interpretation of pilot results showed that most of the incremental oil and back produced enriched hydrocarbons came from one well. During the follow-up CO2 injection phase, one of the horizontal wells completed in the gas cap (unlike other pilot producers), was redrilled deeper into the oil column to improve the pilot areal and vertical sweep.
The pilot design, results, and interpretation will be discussed. Results from the pilot will be used to support evaluation of a field wide development, which could lead to substantial incremental reserves and extension of the field life.
Andersen, Pål Østebø (Dept. of Energy Resources, University of Stavanger) | Lohne, Arild (The National IOR Centre of Norway, University of Stavanger) | Stavland, Arne (The National IOR Centre of Norway, University of Stavanger) | Hiorth, Aksel (Dept. of Energy Resources, University of Stavanger) | Brattekås, Bergit (Dept. of Energy Resources, University of Stavanger)
Capillary spontaneous imbibition of solvent (brine bound in gel) from formed polymer gel into an adjacent, oil-saturated porous medium was recently observed in laboratory experiments. Loss of solvent from the gel by spontaneous imbibition may influence the blocking capacity of the gel residing in a fracture, by decreasing the gel volume, and may contribute to gel failure, often observed in water-wet oil fields. Formed gel cannot enter significantly into porous rock, which has important implications for spontaneous imbibition: the gel particle network itself is not imbibed, and remains close to the rock matrix surface, while gel solvent can leave the gel and progress into the matrix due to capillary forces. Polymer gel is an inherently complex fluid and modelling of its behavior is, as such, complicated. Accurate description and quantification of gel properties and behaviour on the laboratory scale is, however, necessary to predict the performance of gel placed in an oil field, particularly in fractured formations. In this work, we present an original modelling approach, to simulate and interpret spontaneous solvent imbibition from Cr(III)-Acetate HPAM gel into oil-saturated chalk core plugs. A theory describing solvent flow within a gel network is detailed, and was implemented into an in-house simulator. Simulations of spontaneous imbibition from gel was performed, and compared to free spontaneous imbibition of water. A good overall match was achieved between experiments and simulations on the core scale, which validates the proposed gel model.
All Faces Open (AFO) and Two Ends Open - Free Spontaneous Imbibition (TEOFSI) boundary conditions were used in the experiments, and formed the basis for simulation. Spontaneous imbibition occurs at the core end faces that are open to flow and exposed to gel (different for the two boundary conditions). The gel surrounding the core was discretized and included as a part of the total grid to capture transient behavior. The surrounding gel is treated as a compressible porous medium where the gel's polymer structure constitutes the matrix having constant solid volume while the gel porosity is a function of pore pressure. The gel permeability is modelled as function of gel porosity using a Kozeny-Carman approach. The flow equations for the gel and core domains were solved simultaneously by implementing the proposed description into the core scale simulator IORCoreSim. Two properties were identified to control the transport of water from gel into the adjacent matrix: the permeability and compressibility of the gel. The flow of water from the gel was observed in simulations to occur in a transient manner, driven by the coupled gradients in gel fluid pressure and gel porosity, where the gel porosity initially decreases in a layer close to the core surface due to reduced aqueous pressure. Gel porosity continued to decrease in layers away from the core surface; the propagation rate was controlled by two main gel parameters: (i) Gel compressibility controlled the pressure gradient within the gel network, and the amount of water transported from the outer part of the gel towards the core surface to balance the pore pressure. (ii) Gel permeability limited how fast water could flow within the gel at a given pressure gradient, thus increasing the time scale of the overall imbibition process.
The Niobrara and Codell in the Wattenberg Field of the Denver-Julesburg Basin (DJ Basin)have been in the centerstage of horizontal drilling and multi-stage hydraulic fracturing ever since 2007. Based on the current well completion strategy, oil rates drop to 20 bbl/day/well in five years of primary production. The cumulative primary production in the first five years amounts to 3%. Nonetheless, a substantial amount of producible hydrocarbon still remains. In this paper, we propose a most feasible enhanced oil recovery (EOR) technique for the Niobrara and Codell and other similar unconventional oil reservoirs. Realizing the unavailability of CO2 in the area while having easy access to methane, ethane, propane and butane, we designed an injecting gas consisting of ethane enriched with methane, propane and butane for EOR. A dual-porosity compositional model was constructed using data from seismic, well logs, core analysis, and production performance. After successful history matching, as well as verification with seismic and microseismic interpretations, a producer with five years of production history was converted to an EOR-gas injector in the numerical model. We used the model to determine the optimal injection gas composition for producing the largest amount of oil. We also studied the contribution of molecular diffusion at the fracture-matrix interface for the incremental oil recovery from gas injection. Model results indicate that converting three producers to injector wells, and producing from the remaining eight producers, yielded total oil recovery of 4.68% in fifteen years of production with 13% of which attributed to gas injection EOR.
Spontaneous and forced imbibition are recognized as important recovery mechanisms in naturally fractured reservoirs as the capillary force controls the movement of the fluid between the matrix and the fracture. For unconventional reservoirs, imbibition is also important as the capillary pressure is more dominant in these tighter formations, and the theoretical understanding of the flow mechanism for the imbibition process will benefit the understanding of important multiphase flow phenomenons like water blocking. In this paper, a new semi-analytic method is presented to examine the interaction between spontaneous and forced imbibition and to quantitatively represent the transient imbibition process. The methodology solves the partial differential equation of unsteady state immiscible, incompressible flow with arbitrary saturation-dependent functions using the normalized water flux concept, which is very identical to the fractional flow terminology used in traditional Buckley-Leverett analysis. The result gives a universal inherent relationship between time, normalized water flux, saturation profile and the ratio between co-current and total flux. The current analysis also develops a novel stability envelope outside of which the flow becomes unstable due to strong capillary forces, and the characteristic dimensionless parameter shown in the envelope is derived from the intrinsic properties of the rock and fluid system and can describe the relative magnitude of capillary and viscous forces at the continuum scale. This dimensionless parameter is consistently applicable in both capillary dominated and viscous dominated flow conditions.
Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H. (New Mexico Institute of Mining & Technology) | Nwachukwu, C. (New Mexico Institute of Mining & Technology) | Alebiosu, O. (ConocoPhillips Co) | Shabani, B. (Oklahoma State University)
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
Recent studies have shown that enhanced oil recovery will be the focal point for approximately 50% of the global oil production in the upcoming two-three decades. According to the several ballpark studies conducted on EOR techniques, results show that for reservoirs with oil viscosities ranging from 10 to 150 m Pa.s., polymer flooding seems to be an ideal development strategy. However, when the oil viscosities exceed 150 m Pa.s., polymer injectivity and pumping efficiencies can turn out to be major inhibiting factors, thereby limiting the range of oil viscosities for which polymer flooding can be utilized. The core reason for this is that the values of viscosity for the injected water containing polymer, calculated for the beneficial mobility ratio, can lead to the inhibiting factor stated above.
Previously conducted lab studies have shown that supramolecular systems are very resistant in high temperature - high salinity systems. To be able to achieve the easier injection, the injected supramolecular viscosity will be kept at lower values and then increased to the levels right before or upon contacting the oil in the reservoir.
The core difference between conventional polymer systems and supramolecular polymer systems is that the latter disassemble and re-assemble as opposed to degradation when exposed to extreme shear stress and temperatures. It can therefore be said that supramolecular polymer systems are self-healing in nature. The phenomenon has been observed in cases where polymers with high molecular weight are forced through narrow flow channels. Though molecular division takes place, supramolecular systems have shown a tendency of reassembly later on. Therefore, adaptability of these systems to bounded or restricted environments can be established.
This study will add the modeling and simulation components of supramolecular systems which can be effectively utilized in high temperature-high salinity conditions through adjustments to viscosities and interfacial properties of these assemblies. This will help compare the displacement efficiency of supramolecular systems which efficiently perform in a wide range of reservoirs such as thin zones, and reservoirs within permafrost conditions. This can significantly benefit the oil and gas companies worldwide in preparing a technically feasible, but also, a cost effective EOR development strategy, whenever polymer injection is of consideration.
Holubnyak, Yevhen (Kansas Geological Survey) | Watney, Willard (Kansas Geological Survey) | Hollenbach, Jennifer (Kansas Geological Survey) | Rush, Jason (Kansas Geological Survey) | Fazelalavi, Mina (Kansas Geological Survey) | Bidgoli, Tandis (Kansas Geological Survey) | Wreath, Dana (Berexco LLC)
Baseline geologic characterization, geologic model development, studies of oil composition and properties, miscibility pressure estimations, geochemical characterization, reservoir modelling were performed. In March of 2015 the injection well (class II) KGS 2-32 was drilled, cored, and logged through an entire anticipated injection interval. Whole core samples were obtained and tested for porosity and permeability, relative permeability, and capillary pressure. The Drill Stem Test (DST) was also conducted to estimate injection interval permeability and pore-pressure. After the injection well KGS 2-32 was acidized, Step Rate (SRT) and Interference (IT) tests were conducted and analysed for permeability, well pattern communication, and fracture closing pressure.
Approximately 20,000 metric tons of CO2 was injected in the upper part of the Mississippian reservoir to verify CO2 EOR viability in carbonate reservoirs and evaluate a potential of transitioning to geologic CO2 storage through EOR. Total of 1,101 truckloads, 19,803 metric tons, average of 120 tonnes per day were delivered over the course of injection that lasted from January 9 to June 21, 2016. After cessation of CO2 injection, KGS 2-32 well was converted to water injector and is currently continues to operate. CO2 EOR progression in the field was monitored weekly with fluid level, temperature, and production recording, and formation fluid composition sampling.
As a result of CO2 injection observed incremental average oil production increase is ~68% with only ~18% of injected CO2 produced back. Simple but robust monitoring technologies proved to be very efficient in detection and locating of CO2. High CO2 reservoir retentions with low yields within actively producing field could help to estimate real-world risks of CO2 geological storage.
Wellington filed CO2 EOR was executed in a controlled environment with high efficiency. This case study proves that CO2 EOR could be successfully applied in Kansas carbonate reservoirs if CO2 sources and associated infrastructure is available.
CO2 enhanced oil recovery is usually affected by poor sweep efficiency due to unfavorable mobility contrast between the injected CO2 and oil. To alleviate this problem, CO2 is added to the injected brine and transported in the reservoir by flood water. Therefore, Carbonated Water Injection (CWI), takes advantage of both CO2 and water flooding processes. Furthermore, geochemical reactions between the injected carbonated brine and rock can alter petrophysical properties of the reservoir and affect final oil recovery. While there are several CWI coreflood experiments reported in the literature, simulation studies for this process are scarce.
Accurate modeling of CWI performance requires a simulator with the ability to capture true physics of the CWI process. In this study, a compositional reservoir simulator developed at The University of Texas at Austin, UTCOMP, coupled with a state-of-the-art geochemical package developed by United States Geological Survey, IPhreeqc, is used to model CWI process. We considered the impact of CO2 mass transfer between brine and hydrocarbon phases based on thermodynamic constrains at the reservoir condition. In order to validate our simulation approach, the results of our CWI simulations were compared with a recently published coreflood experiment. Moreover, we investigated the fluid-rock interactions in CWI.
The results of the simulations, indicated that prior to water breakthrough the main drive mechanism is displacement. But as more carbonated water is injected, CO2 diffuses more into the trapped oil left behind, which results in oil swelling and subsequent oil viscosity reduction. Moreover, reaction of carbonate minerals such as calcite with carbonated brine results in dissolution of the main rock matrix which consequently creates wormholes similar to carbonates acidizing.
In this study we propose a novel approach for accurate modeling of carbonated waterflooding process. The results of this study highlight the importance of geochemical reactions in modeling CWI process. Our approach has been validated based on history matching at the backdrop of a recently published coreflood experiment.